Title:
SURFACE MULTIPLE WELL
Kind Code:
A1


Abstract:
An offshore oil production system, comprising a structure in a body of water, having a portion extending above a surface of the body of water; a surface wellhead located at a top of the body of water; a first wellhead located at a bottom of the body of water; a second wellhead located at a bottom of the body of water; a first riser extending from the first wellhead to the surface wellhead; and a second riser extending from the second wellhead to the surface wellhead.



Inventors:
Lau, Hon Chung (Bellaire, TX, US)
Application Number:
13/881604
Publication Date:
08/22/2013
Filing Date:
10/26/2011
Assignee:
LAU HON CHUNG
Primary Class:
International Classes:
E21B17/01; E21B33/035
View Patent Images:
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Primary Examiner:
BUCK, MATTHEW R
Attorney, Agent or Firm:
SHELL USA, INC. (HOUSTON, TX, US)
Claims:
1. An offshore oil production system, comprising: a structure in a body of water, having a portion extending above a surface of the body of water; a surface wellhead located at a top of the body of water; a first wellhead located at a bottom of the body of water; a second wellhead located at a bottom of the body of water; a first riser extending from the first wellhead to the surface wellhead; and a second riser extending from the second wellhead to the surface wellhead.

2. The system of claim 1, further comprising a first wellbore extending further into a subsea formation beneath the body of water and beneath the first wellhead, and further comprising a second wellbore extending further into the subsea formation beneath the body of water and beneath the second wellhead.

3. The system of claim 2, further comprising a production tubing within each of the first wellbore and the second wellbore.

4. The system of claim 3, wherein each production tubing extends from first wellbore and the second wellbore to the surface wellhead.

5. The system of claim 1, further comprising an outer riser extending from the surface wellhead at least a portion of the distance towards the first and second wellheads, the first riser and the second riser located within the outer riser.

6. The system of claim 5, wherein the outer riser comprises at least one divider to separate the riser into at least two regions.

7. The system of claim 2, wherein the first wellbore further comprises a casing string.

8. The system of claim 1, wherein the surface wellhead comprises at least two surface trees.

9. The system of claim 1, wherein the structure comprises a tension leg platform.

10. The system of claim 1, wherein the structure comprises a spar platform.

Description:

BACKGROUND OF INVENTION

1. Field of the Invention

The present invention is directed to multiple risers located within a single wellhead for deepwater applications.

2. Background Art

U.S. Patent Application Publication 2010/0126729 discloses systems and methods usable to operate on a plurality of wells through a single main bore. One or more chamber junctions are provided in fluid communication with one or more conduits within the single main bore. Each chamber junction includes a first orifice communicating with the surface through the main bore, and one or more additional orifices in fluid communication with individual wells of the plurality of wells. Through the chamber junctions, each of the wells can be individually or simultaneously accessed. A bore selection tool having an upper opening and at least one lower opening can be inserted into the chamber junction such that the one or more lower openings align with orifices in the chamber junction, enabling selected individual or multiple wells to be accessed through the bore selection tool while other wells are isolated from the chamber junction. U.S. Patent Application Publication 2010/0126729 is herein incorporated by reference in its entirety.

U.S. Pat. No. 5,775,420 discloses a dual completion for gas wells including a dual base with a primary hanger incorporated in the base. Primary and secondary coiled tubing strings extend through the base at a downwardly converging angle of 2 DEG or less. The dual base is mounted on an annular blowout preventer. At the top of the annular blowout preventer is a tubing centralizer that aligns the two tubing strings parallel to one another. The blowout preventer has two side ports below the bladder allowing the operator to produce gas from the annulus, to flare gas to atmosphere or to pump in kill fluid in the event of an emergency. The alignment of the tubing strings allows production recorders to be run in either string. U.S. Pat. No. 5,775,420 is herein incorporated by reference in its entirety.

U.S. Pat. No. 3,601,196 discloses a method for perforating in a dual, parallel pipe string tubingless well. A crossover passage or port connects these pipe strings. Each pipe string is provided with a landing nipple at about the same depth below the crossover port. A radioactive source tool, which includes a radioactive pill for transmitting radiation in angular directions and a seating member for seating the radioactive source tool in the landing nipple arranged in one of the pipe strings, is pumped through the one pipe string until the seating member is landed in the landing nipple. The radioactive pill is suspended from the seating member a predetermined distance which is approximately the level at which it is desired to perforate. A perforating assembly, which includes a directional perforating gun, a directional radiation detector, a radioactivity-sensitive gun-firing mechanism including a source of electrical power for causing actuation of the perforating gun, a rotation device for causing the perforating gun to rotate, a seating member for seating the perforating assembly in the landing nipple arranged in the other pipe string, and a locomotive device for moving the perforating assembly through the other pipe string, is then pumped through the other pipe string until the seating member lands in the landing nipple. The detector of the perforating assembly is suspended a predetermined distance from the seating member so that it is positioned at the same level as the radioactive pill in the adjacent pipe string. The firing mechanism utilizes a switch which is actuated when the radioactive count detected by the radiation detector reaches a predetermined level. The directional gun is aimed so as to fire in a predetermined angular direction when the directional detector is facing the radioactive pill. The perforating assembly is rotated by circulating fluid in the pipe strings. After the perforating gun has fired, the perforating assembly is removed from the other pipe string. The radioactive source tool is then removed from the one pipe string. The perforating gun may be reloaded and the perforating procedure repeated at a different level in the well bore after repositioning the radioactive source tool and perforating assembly. U.S. Pat. No. 3,601,196 is herein incorporated by reference in its entirety.

U.S. Pat. No. 7,066,267 discloses a splitter assembly is positioned downhole within a conductor for separating two or more tubular strings placed within the conductor. A splitter housing may include a first bore and a second bore for separating a first well from a second well, and a plug positioned in one of the bores including a top face sloping downwardly toward the other bore. One or more guide plates secured to the splitter housing and positioned above the plug guide a bit or other tool toward one of the first bore and the second bore. The splitter housing may be positioned along the conductor after the conductor is jetted in place. According to the method, the plug in one of the bores is retrieved after a casing is run in one well, so that the second bit and the second casing will pass through the bore which previously included the plug. U.S. Pat. No. 7,066,267 is herein incorporated by reference in its entirety.

SUMMARY OF INVENTION

One aspect of the invention provides an offshore oil production system, comprising a structure in a body of water, having a portion extending above a surface of the body of water; a surface wellhead located at a top of the body of water; a first wellhead located at a bottom of the body of water; a second wellhead located at a bottom of the body of water; a first riser extending from the first wellhead to the surface wellhead; and a second riser extending from the second wellhead to the surface wellhead.

Advantages of the invention include one or more of the following:

Reduced size tree deck on an offshore structure;

Reduced size offshore structure; and/or

Increased number of risers connected to an offshore structure.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram of a multiple wellhead system configured with a tension leg platform in accordance with embodiments disclosed herein.

FIG. 2 is a cross-sectional view of a multiple wellhead system in accordance with embodiments disclosed herein.

FIG. 3 is a schematic diagram of a multiple wellhead system configured with a spar platform in accordance with embodiments disclosed herein.

FIG. 4 is a top view of a conventional tree deck of a spar platform having single wellheads disposed thereon.

FIG. 5 is a top view of a tree deck on a spar platform having multiple wellhead systems in accordance with embodiments disclosed herein.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to a multiple wellhead system. More specifically, embodiments disclosed herein relate to a multiple wellhead system that may be used in deepwater applications with, for example, a tension leg platform (TLP) or a spar platform, or other fixed or floating structures as are known in the art.

FIG. 1

Referring to FIG. 1, a schematic diagram of a TLP multiple wellhead system in accordance with embodiments disclosed herein is shown. In this embodiment, a multiple wellhead 110 may be connected to a TLP 100 to allow fluid to flow from multiple subsea wellheads (e.g., subsea wellheads 140 and 150) to TLP 100. In this embodiment, TLP 100 may be an offshore floating platform above sea level 181. Further, TLP 100 may be used for production of fluids in deepwater applications and may be vertically tethered to seafloor 180 by tethers or tendons (not shown) to mitigate vertical and/or horizontal movement of TLP 100. The tethers or tendons may have a high axial stiffness and a low elasticity to mitigate any vertical movement of TLP 100. However, those having ordinary skill in the art will appreciate that the tethers or tendons may be any type of structure disposed between the TLP and the sea floor that may mitigate vertical and/or horizontal movement of the TLP.

TLP 100 may include multiple decks and levels (e.g., a main deck 102, a weather deck 104, a rig skid base 105, and a drill floor 109) from which to secure and suspend drilling and production risers (e.g., a drilling riser 108 and production risers 124 and 134). In this embodiment, drilling riser 108 is suspended by a drilling riser tensioner 107 at rig skid base 105, below drill floor 109. However, those having ordinary skill in the art will appreciate that a riser may be suspended by a tensioner at other various positions on a TLP. Drilling riser tensioner 107 may be used to prevent outer drilling riser 108 from experiencing extreme forces that may result from vertical movement of TLP 100 due to currents, storms, etc. For example, drilling riser tensioner 107 may prevent drilling riser 108 from buckling if TLP 100 were to move downward. Similarly, drilling riser tensioner 107 may prevent outer drilling riser 108 from experiencing extreme tension forces if TLP 100 were to move upward. Although, in this embodiment, TLP 100 is shown having a drilling riser and a drilling riser tensioner (e.g., drilling riser 108 and drilling riser tensioner 107) separate from a production riser and a production riser tensioner (e.g., production risers 124 and 134 and production riser tensioner 117), those having ordinary skill in the art will appreciate that separate drilling risers and tensioners and production risers and tensioners may not be necessary. For example, once drilling has been completed, a drilling riser may be removed from a riser tensioner and removed from a TLP and one or more production risers may be configured to engage with the tensioner and may replace the drilling riser in the TLP.

As shown in FIG. 1, a blowout preventer (BOP) stack 106 is connected to outer drilling riser 108. In this embodiment, BOP stack 106 may be configured to seal, control, and monitor an oil or gas well (not shown). BOP stack 106 may also be configured to control pressure changes within outer drilling riser 108, which may prevent a outer drilling riser 108 or drilling or production fluid from being blown out of an oil or gas well. One having ordinary skill in the art will appreciate that BOP stack 106 may include one or more ram-type BOPs, annular BOPs, or combinations thereof. Although BOP stack 106 is shown connected to outer drilling riser 108, those having ordinary skill in the art will appreciate that a BOP stack may be connected to several different tubular members. For example, a BOP stack may be connected to drill pipe, production pipe, or well casing.

As shown in FIG. 1, multiple wellhead 110 is suspended by a production riser tensioner 117 at main deck 102, below weather deck 104. However, those having ordinary skill in the art will appreciate that a multiple wellhead may be positioned at various other positions on a TLP. For example, production riser tensioner 117 may be used to prevent production risers 124 and 134 from experiencing extreme forces that may result from vertical movement of TLP 100. Further, production riser tensioner 117 may prevent production risers 124 and 134 from buckling if TLP 100 were to move downward. Similarly, production riser tensioner 117 may prevent production risers 124 and 134 from experiencing extreme tension forces if TLP 100 were to move upward. Those having ordinary skill in the art will appreciate that a tensioner may be any apparatus or mechanism that may control the vertical position of a tubular member. For example, a tensioner may be a system of hydraulically controlled cylinders that may be operated and adapted to control the vertical position of a tubular member.

As shown, multiple wellhead 110 is connected to production risers 124 and 134. Multiple wellhead 110 allows one or more risers to connect simultaneously to a single wellhead on a floating platform (e.g., TLP 100) and extend downward toward multiple subsea wellheads (e.g., subsea wellheads 140 and 150). Although multiple wellhead 110 is shown connected to two risers, production risers 124 and 134, those having ordinary skill in the art will appreciate that a multiple wellhead may be connected to one or more risers. For example, a multiple wellhead may be connected to three or four risers, which may be used to produce fluid from multiple subsea wellheads.

As shown in FIG. 1, subsea wellheads 140 and 150 are located on seafloor 180 and may provide a suspension point and pressure seals for tubular members, such as casing strings, pipes, or risers (e.g., production risers 124 and 134). As fluids are produced from the formation through subsea wellheads 140 and 150, production risers 124 and 134 allow the production fluids to travel from the subsea wellheads 140 and 150 to the multiple wellhead 110 on TLP 100.

FIG. 2

Referring to FIG. 2, a cross-sectional view of a multiple wellhead system in accordance with embodiments disclosed herein is shown. In this embodiment, an outer production riser 212 is connected to a multiple wellhead 210. As shown in FIG. 2, outer production riser 212 extends from multiple wellhead 210 and splits into two outer production risers 224 and 234. Those having ordinary skill in the art will also appreciate that an outer production riser (e.g., outer production riser 212) that joins two separate risers (e.g., production riser 224 and 234) may not be necessary to allow fluid to travel separately to the surface (e.g. to multiple wellhead 210). For example, two separate production risers may be separately connected to a multiple wellhead, without the use of an outer riser joining the two risers, and may allow fluid to travel separately through the two production risers to the surface.

Further, as shown in FIG. 2, production riser 224 includes an outer production riser 220 and an inner production riser 222, in which inner production riser 222 is disposed within outer production riser 220. Similarly, production riser 234 includes an outer production riser 230 and an inner production riser 232, in which inner production riser 232 is disposed within outer production riser 230. Having an inner production riser (e.g., inner production risers 222 and 232) disposed within an outer production riser (e.g. outer production risers 220 and 230) may allow the risers to function in extreme pressure environments, such as deepwater environments. For example, having an inner production riser disposed within an outer production riser in a deepwater environment may mitigate the pressure acting on the inner production riser, as the outer production riser may serve as a buffer between the inner production riser and the deepwater environment. Further, having an inner production riser disposed within an outer production riser may also minimize or prevent the inner production riser from being damaged by the surrounding environment, as the outer production riser may protect the inner production riser by shielding the inner production riser and, again, serving as a buffer between the inner production riser and the surrounding environment.

As shown, a centralizer 260 is disposed within outer production riser 212 and may provide both lateral and vertical stability for inner production risers 222 and 232, which are also disposed within outer production riser 212. Centralizer 260 may be any body or mechanism that may provide lateral and vertical stability for inner production risers 222 and 232. For example, centralizer 260 may be a plate configured to engage with inner production risers 222 and 232 to provide lateral stability to the inner production risers. Further, the centralizer 260 may be a spring or pulley mechanism configured to engage with the inner production risers 222 and 232 to provide vertical stability to the inner production risers 222 and 232. Further, in one embodiment, a partition 215 may be disposed within outer production riser 212. Partition 215 may extend within outer production riser 212, from multiple wellhead 210 to a junction 219, in which outer production riser 212 splits into production risers 224 and 234. In this embodiment, partition 215 may separate inner production risers 222 and 232 within outer production riser 212. Partition 215 may be any plate, divider, member, or body that may provide a physical separation between inner production risers 222 and 232.

Although junction 219 is illustrated as being below the water level, in some embodiments, junction 219 is above the water level.

Further, as shown in FIG. 2, production risers 224 and 234 are connected to subsea wellheads 240 and 250, respectively. Subsea wellheads 240 and 250 are located on seafloor 280 and may provide a suspension point and pressure seals for tubular members, such as casing strings, pipes, or risers (e.g., production risers 224 and 234). As fluids are produced from subsea wellheads 240 and 250, production risers 224 and 234 allow the production fluids to travel from the subsea wellheads 240 and 250 to the multiple wellhead 210. In this embodiment, fluids that are produced from subsea wellheads 240 and 250 travel through tubings (not drawn) insider inner production risers 222 and 232, respectively, to the multiple wellhead 210. However, those having ordinary skill in the art will appreciate that inner production risers disposed within outer production risers may not be necessary to allow fluids to travel from subsea wellheads to the surface (e.g. to a multiple wellhead). For example, fluids may travel from subsea wellheads through tubular members that are connected to the subsea wellheads, such as pipes or risers without an interior tubular member disposed within, to the surface.

FIG. 3

Referring to FIG. 3, a schematic diagram of a multiple wellhead system configured with a spar platform in accordance with embodiments disclosed herein is shown. In this embodiment, a multiple wellhead 310 may be connected to a spar platform 300 to allow fluid to flow from multiple subsea wellheads (e.g., subsea wellheads 340 and 350) to a spar platform 300. In this embodiment, spar platform 300 may be an offshore floating platform at sea level 381. Further, spar platform 300 may include a counterweight 311 disposed within a main body 301 of spar platform 300, which may help stabilize spar platform 300. Counterweight 311 of spar platform 300 may be filled with water or any other material known in the art and may assist in stabilizing spar platform 300 in offshore conditions. Further, mooring lines (not shown) may be connected to spar platform 300 and may assist in anchoring spar platform 300 to the seafloor 380. Mooring lines may be flexible members that may connect spar platform 300 to the seafloor 380. Heave plates and buoyancy modules (not shown) may also be provided on body 301.

Spar platform 300 may include multiple decks and levels (e.g., a drill floor 309 and a cellar deck 302) from which to secure and suspend drilling and production risers. In this embodiment, production risers 324 and 334 are suspended by a production riser tensioner 317 at cellar deck 302, below drill floor 309. However, those having ordinary skill in the art will appreciate that a riser may be suspended by a tensioner at other various positions on a spar platform.

Production riser tensioner 317 may be used to prevent production risers 324 and 334 from experiencing extreme forces that may result from vertical movement of spar platform 300. For example, production riser tensioner 317 may prevent production risers 324 and 334 from buckling if spar platform 300 were to move downward. Similarly, production riser tensioner 317 may prevent production risers 324 and 334 from experiencing extreme tension forces if spar platform 300 were to move upward.

As shown in FIG. 3, multiple wellhead 310 is connected to production risers 324 and 334. In this embodiment, multiple wellhead 310 allows multiple risers to connect simultaneously to a single wellhead on a floating platform (e.g., spar platform 300) and extend downward toward multiple subsea wellheads (e.g., subsea wellheads 340 and 350). As discussed above, although multiple wellhead 310 is shown connected to two risers, production risers 324 and 334, those having ordinary skill in the art will appreciate that a multiple wellhead may be connected to one or more risers. For example, a multiple wellhead may be connected to three or four risers, which may be used to produce fluid from multiple subsea wellheads.

Further, as shown in FIG. 3, production risers 324 and 334 exit main body 301 of spar platform 300 at a keel point 319 and connect to subsea wellheads 340 and 350, respectively. Subsea wellheads 340 and 350 are situated on seafloor 380 and may provide a suspension point and pressure seals for tubular members, such as casing strings, pipes, or risers (e.g., production risers 324 and 334). As fluids are produced from the formation through tubings (not drawn) to the subsea wellheads 340 and 350, production risers 324 and 334 may allow the production fluids to travel through the tubings from the subsea wellheads 340 and 350 to the surface (e.g., multiple wellhead 310 on spar platform 300).

FIG. 4

Referring to FIG. 4, a top view of a conventional tree deck of a spar platform having single wellheads disposed thereon is shown. Specifically, FIG. 4 shows a conventional tree deck 474 of a spar platform 402 having thirty-two single wellheads 412 disposed thereon, each configured to engage with a single riser (not shown). Each riser may be configured to connect with a single subsea wellhead (not shown). As such, the tree deck 474 of spar platform 402 may be configured to connect with thirty-two subsea wellheads. A tree deck (e.g. tree deck 474) may be any deck on an offshore platform (e.g., spar platform 402) in which wellheads and/or BOP trees (e.g. single wellheads 412) are located.

FIG. 5

Referring now to FIG. 5, a top view of a tree deck on a spar platform having multiple wellheads in accordance with embodiments disclosed herein is shown. Specifically, FIG. 5 shows a top view of a tree deck 572 on a spar platform 500 having sixteen multiple wellheads 510, each configured to engage with two risers. As discussed above, each riser may be configured to connect with a single subsea wellhead. As such, the tree deck 572 of spar platform 500 may be configured to connect with thirty-two subsea wellheads.

Referring generally to FIGS. 4 and 5, although the number of multiple wellheads 510 (sixteen) may be half of the number of wellheads 412 (thirty-two), both tree decks 572 and 474 may connect to the same number risers (thirty-two) and, thus, connect to the same number of subsea wellheads (thirty-two). Because the number of multiple wellheads 510 is less than the number of wellheads 412, as shown in FIGS. 5 and 4, respectively, the surface area of tree deck 572 may be less than the surface area of tree deck 474. As such, the overall size of spar platform 500 may be smaller than the overall size of spar platform 402. Although FIGS. 4 and 5 are shown having thirty-two and sixteen wellheads, respectively, those having ordinary skill in the art will appreciate that the number of wellheads on an offshore platform is not limited to these quantities. For example, an offshore platform may include more or less than the number of wellheads described above.

Although the number of subsea wellheads that may be accessed by risers may be the same (e.g. thirty-two) in FIGS. 4 and 5, the surface area required for tree deck 572 having multiple wellheads 510 may be less than the surface area required for tree deck 474 having wellheads 412. Accordingly, the surface area required for a tree deck on a spar platform may be reduced by increasing the number of risers that may be configured with each wellhead on the tree deck. Although FIGS. 4 and 5 refer to configurations of a tree deck on a spar platform, those having ordinary skill in the art will appreciate that increasing the number of risers that may be configured with each wellhead may reduce the surface area required for a tree deck on any deepwater platform. For example, increasing the number of risers that may be configured with each wellhead may reduce the surface area required for a tree deck on a TLP.

Illustrative Embodiments

In one embodiment, there is disclosed an offshore oil production system, comprising a structure in a body of water, having a portion extending above a surface of the body of water; a surface wellhead located at a top of the body of water; a first wellhead located at a bottom of the body of water; a second wellhead located at a bottom of the body of water; a first riser extending from the first wellhead to the surface wellhead; and a second riser extending from the second wellhead to the surface wellhead. In some embodiments, the system also includes a first wellbore extending further into a subsea formation beneath the body of water and beneath the first wellhead, and further comprising a second wellbore extending further into the subsea formation beneath the body of water and beneath the second wellhead. In some embodiments, the system also includes a production tubing within each of the first wellbore and the second wellbore. In some embodiments, each production tubing extends from first wellbore and the second wellbore to the surface wellhead. In some embodiments, the system also includes an outer riser extending from the surface wellhead at least a portion of the distance towards the first and second wellheads, the first riser and the second riser located within the outer riser. In some embodiments, the outer riser comprises at least one divider to separate the riser into at least two regions. In some embodiments, the first wellbore further comprises a casing string. In some embodiments, the surface wellhead comprises at least two surface trees. In some embodiments, the structure comprises a tension leg platform. In some embodiments, the structure comprises a spar platform.

Embodiments described herein may provide for one or more of the following advantages. In accordance with the present disclosure, production fluids may be produced from multiple subsea wellheads to a single multiple wellhead disposed on a floating platform, such as a TLP or spar platform.

However, those having ordinary skill in the art will appreciate that the multiple wellhead system, described above, may be adapted to be used on floating platforms other than a TLP or spar platform. Space for multiple wellheads may be limited on an offshore platform for deepwater fluid production applications, as construction and maintenance costs may increase as the size of the offshore platform increases. Further, constructing and maintaining the offshore platforms may also become more costly as the size of the offshore platform increases. The multiple wellhead system described above may reduce the number of floating offshore platforms needed for producing fluids in deepwater conditions, because the multiple wellhead system may allow fluids to be produced from multiple subsea wellheads to a single multiple wellhead on an offshore platform. Alternatively, any extra space that may be available on existing offshore platforms as a result of the multiple wellhead system, described above, may be used for other equipment and processes.

While the present invention has been described in terms of various embodiments, modifications in the apparatus and techniques described herein may be made without departing from the concept of the present invention. It should be understood that embodiments and techniques described in the foregoing are illustrative and are not intended to limit the scope of the invention.